The present invention relates to enhancing the permeability of subterranean formations for the production of hydrocarbons through stimulation, and more particularly, to stimulation methods for enhancing the permeability of liquid-sensitive subterranean formations. “Liquid-sensitive subterranean formations” are those subterranean formations that are sensitive to liquids (whether aqueous or hydrocarbon). These formations may form undesirable precipitates when contacted with an aqueous liquid, for example. In other instances, for example in a dry CBM well in Canada, the combination of very low porosity with very low reservoir pressure may trap an aqueous liquid, i.e., the capillary pressure is higher than the reservoir pressure so the reservoir pressure cannot expel the liquid once it gets into the pores of the formation. One type of liquid-sensitive subterranean formation is a dry coal bed methane (“CBM”) formation. A “dry coal bed methane” formation as that term is used herein refers to a coal formation that does not produce an appreciable level of free water. Another example is a low water content CBM formation. A “low water content CBM” formation as that term is used herein refers to a CBM formation that may produce some free water, but not a continuous volume. Other examples include any formation that can be hydraulically stimulated where aqueous liquid sensitivity is an issue (e.g., shale gas wells with ultra-low permeability, undersaturated or underpressured reservoirs). An “ultra-low permeability” formation as that term is used herein refers to a formation having a permeability of less than 0.1 mD. A “low permeability” formation as that term is used herein refers to a formation having a permeability of about 1 mD or less. A dry gas well that can produce water is an example of a potentially hydrocarbon liquid sensitive situation because introduction of a hydrocarbon may impact the relative permeability because the hydrocarbon can act as a trapped phase in the pore system. Formations that contain a large amount of organic shales may behave similarly.
Coal is the most abundant fossil fuel in the world; its recoverable reserves amount to almost 100 quintillion BTU of energy, nearly 15 times the total energy content estimated for known reserves of petroleum. People have mined coal and used it for heat for centuries. However, relatively recently coal has been recognized for being the origin and source for coal bed methane gas, another valuable hydrocarbon fuel. Coal bed methane gas consists primarily of methane (e.g., 95%) but may also contain ethane, propane, and higher homologs. At times, the volume of coal bed methane may be estimated to be about 400 trillion standard cubic feet (SCF) of gas in place, most of it adsorbed on coal in seams buried at a depth of less than 9000 feet (ft) from the surface, and almost half of it is on coal seams buried less than 3000 ft, too deep to mine but easily penetrated by a well bore using conventional drilling techniques. Coal beds are, therefore, reservoirs and source rocks for a huge amount of gas that can be produced, in part, through a well bore. Much research has been directed to recovering coal bed methane.
Coal is a dual porosity rock consisting of micropores and a network of natural fractures known as cleats. The term “cleats” as used herein with respect to coal seams includes openings or pathways in the rock that are generally more or less vertical or transverse to the bedding plane, along which no appreciable movement between the surfaces of either side of the opening has occurred. At the time of our discovery, it is believed that the cleat network and micropores in a coal seam are saturated with water, and methane is adsorbed to the surface of coal. Reservoir pressure depletion is a mechanism currently being employed to desorb methane from coal. When production of coal bed methane is initiated, water contained in the coal cleat network flows to the well bore, as per Darcy's Law. This leads to a reduction in reservoir pressure, which in turn, is thought to desorb methane from the coal surface. Thus, the gas production rate from a well may be directly influenced by the speed with which a coal seam is de-watered. While methane migrates from the coal matrix to the cleat network by diffusion, the water contained in the coal micropores (typically 40 Angstrom or smaller pores linked by 5 Angstrom passages) remains essentially immobile due to strong capillary forces. Thus, even though most of the porosity in coal is contained within the micropores, the cleat porosity and its irreducible water saturation are important to a coal bed methane project. Although the above is the common case with coal formations, it has been discovered recently (e.g., in western Canada) that coal systems exist that do not have this mobile water component. These formations may be especially liquid-sensitive.
In an effort to enhance porosity within liquid-sensitive formations such as CBM formations and shale formations, stimulation processes may be used. Compressible gas streams (such as nitrogen) often are used in these stimulation processes rather than aqueous fracturing fluids due to the liquid sensitivity of the formations. A compressible gas hydraulic fracturing process is a stimulation technique which provides the parting energy to break up the natural planes of weakness within the formation rock; a gas squeeze is a technique to impart nitrogen into the formation rock planar structure to expand or otherwise enhance pathways therein. A typical stimulation process usually involves injecting a compressible gas at a high rate and pressure for a short period of time (e.g., minutes vs. hours) into a zone of the formation. “Zone” as used herein simply refers to a portion of the formation and does not imply a particular geological strata or composition. Proppant particulates are not usually used, at least in part, because methods of introducing proppants into gas streams are not yet well developed or in widespread use due to inherent difficulties associated with carrying proppants in a gas stream. These techniques aim to enhance or create pathways within the formation rock through which produced gases may flow. The term “pathway” as used herein refers to any channel, void, or the like that may exist in a liquid-sensitive formation or may be created or enhanced in a subterranean formation through a stimulation technique; no particular mechanism of forming the pathways is implied by the term. Examples of pathways include cleat paths, fractures, microfractures, vertical fractures, horizontal fractures, shattering fractures, face cleats, butt cleats, bedding planes, slickensides, sheet pores, and the like.
In some instances, the bottomhole pumping pressures used may be two to three times the overburden pressure of the formation. In shale gas formations, typical bottomhole pressures would be at some level above the in situ fracturing stress. Additionally, in coal formations or other thin-bedded formation, each seam or zone usually is stimulated separately (e.g., with coiled tubing with a straddle cup packer assembly) from other seams or zones in the formation. Oftentimes, a coal formation may include up to 30 or more seams. Similarly formations with horizontal or deviated well bores through them may be stimulated at specific intervals to enhance gas production along the length of the well bore in contact with the formations. Additionally, these stimulation techniques pressurize and then depressurize the rock in the formation. Upon depressurization, shattering of the rock occurs, which is thought to enhance the desorption of the gas from the matrix. This may enhance diffusivity in addition to permeability.
Hydraulic fracturing of liquid sensitive formations without proppant relies on the rock to “self-prop” (meaning that the surface roughness of each rock face is such that when the fracture closes there is sufficient roughness to allow some conductivity in the fracture face, i.e., the rocks do not go back to a zero tolerance plane) or have enhanced permeability by having the cleats and fracture faces misaligned after the fracture closes. If the rock is soft, these sorts of pathways may not stay open to a sufficient degree. This may be because the fracture faces are not well misaligned, or the fracture face may plug with fines. Additionally, fines may be produced by the fracturing process and any subsequent in situ stress-induced fines generation (e.g., spalling), which can plug any pathways that might otherwise aid production. As a result of, inter alia, this fines migration and rock slippage, the productivity of the hydraulically fractured zone may be reduced significantly.